Abstract:Aging oil，a by-product of oilfield surface production，has complex interface characteristic，as a result，it is difficult to be dehydrated. Using aging oil to develop lubricant for drilling fluid can make use of its emulsifying stability and avoid the difficulties of removing mud，sand and water from aging oil. The components and dosage of lubricant were optimized，and then the performance of lubricant was evaluated. The results showed that the emulsifier for developing lubricant based on aging oil was alkylphenol polyoxyethylene ether（OP-4），the wetting agent was sodium dodecylbenzene sulfonate（ABS），and the stabilizer was sodium carboxymethyl cellulose（Na-CMC）. The optimum formula was obtained as follows：100 mL drilling fluid，3 mL aged oil， 1.5 g OP-4，0.15 g ABS and 0.015 g Na-CMC. The density，apparent viscosity and sticking coefficient of mud cake of the system met the requirements of enterprise standards after the lubricant was added to the bentonite based slurry. Using aged oil as base oil to develop lubricant for drilling fluid was a feasible resource utilization scheme for aged oil.

Abstract:Aiming at the problems of poor retarding effect and difficult injection of retarding acid during the acidizing in high-temperature carbonate reservoir，a retarding thickener（CPAM）was prepared by using dimethyldiallylammonium chloride， acrylamide，K₂S₂O₈ and NaHSO₃ as raw materials. A dual retarding acid system was prepared by compounding CPAM，retarding agent （dodecyltributylphosphine bromide），and retarding dispersant （urea）. The retarding effect and acid etching fracture conductivity of the dual retarding acid at high temperature were studied. The retarding mechanism was analyzed by scanning electron microscopy and contact angle measurement. The results showed that the retarding acid mainly depended on CPAM and urea to improve the film adhesion effect of retarder on the rock surface，and then achieve the purpose of retarding. The optimum formula of dual retarding acid system was obtained as follows：1%—2% retarder，0.1%—0.3% CPAM，1.5% urea. At a temperature of 90 ℃ and a shear rate of 170 s^-1，the viscosity of fresh acid and residual acid corresponding to dual retarding acid system after shearing was less than 10 mPa·s. The retarding efficiency was up to 97% at 90 ℃，which was obviously superior to that of gelling acid. In the high temperature environment of 180 ℃，it had high conductivity retention rate and high-pressure resistance. The dual retarding acid had the advantages of easy injection，high temperature resistance and excellent retarding performance，which was suitable for the acidizing transformation of deep and ultra-deep carbonate reservoir above 180 ℃.

Abstract:The conventional acid fluid stimulation system has inferior high-temperature stability，fast acid rock reaction rate and problematic demulsification. To solve the mentioned problems，a high temperature resistant PGA retarded acid was prepared using polyglycolic acid fluid as the inner phase acid fluid and diesel oil as the outer phase，and adding appropriate surfactants and other additives. The properties of the system，including the stability，shear resistance，acid production capacity，dissolution，were evaluated. The results showed that the optimized PGA retarded acid could remain emulsified state for 76 h at the temperature of 90 ℃. The system could produce 7.91 mol/L H⁺ within 3 h at the temperature of 130 ℃，and more than 9 mol/L H⁺ at continuous reaction. The final apparent viscosity of the system under sheared for 120 min was 31.22 mPa?s and 28.4 mPa?s at the temperature of 130 ℃ and 150 ℃ ，respectively，which conformed to the requirements of the national standard. The static retarded rate of the system to the core was 2.7 times and 2.1 times higher than that of the same concentration of the mud acid and the multiple hydrogen acid system，respectively. In acid-rock reaction experiments，the system could reduce the acid reaction rate by one or two orders of magnitude compared with the multiple hydrogen acid and mud acid system. the static corrosion rate of the system to N80 steel slice was only 3.453 g/（m²?h），which was lower than the standard value. PDA retarded acid exhibited well slow-release performance and weak corrosion，moreover，the degradation products was harmless，which met the requirements of filed processes and had good prospects for sustainable development.

Abstract:For hydraulic fracturing in low-pressure strong hydrophilic tight gas reservoirs，it is necessary to evaluate the influence of the carrier and the usage environment on the performance of the anti-water blocking agent，and to make sure the anti-water blocking agent performs its proper function. Three different types of surfactants，including fluorocarbon anionic surfactant FCY137，fluorocarbon nonionic surfactant FCF102 and self-developed nano FC-ST，had been studied to reduce surface tension and change wettability. By comparing the performance of the solution under different viscosity，APS dosage，mineralization，and pH value，the best anti-water blocking agent were selected，and the waterproof locking capability was evaluated in fracturing fluid， through self-absorbing experiments，adsorption performance experiments sur factant and penetration rate recovery experiments. The results showed that the fluorocarbon anionic surfactant FCY137，fluorocarbon nonionic surfactant FCF102 and nano FC-ST could significantly reduce the surface tension，increase contact angle，effectively reduce the capillary force under the conventional indoor conditions. The nano-FC-ST could maintain stable performance in the fracturing gel-breaking fluid under the condition that the viscosity was less than 4 mPa·s，the temperature was below 120 ℃，APS dosage was 0.5 g/L，the mineralization of water was 1× 105 mg/L and pH value was lower than 11. The performances of the anti-water blocking agent nano surfactant FC-ST met the needs of common low-pressure strong hydrophilic tight gas reservoirs，and it was better than fluorocarbon anionic surfactant FCY137 and fluorocarbon nonionic surfactant FCF102. The slick water of nano FC-ST fracturing fluid could significantly reduce the capillary force，effectively reduce water intrusion，and reduce adsorption in the near well zone. It had a permeability recovery rate of more than 50%，compared with conventional anti-water blocking agent，cleanup additive，the performance was less affected by the carrier and the environment，the performance of the water blockage prevention was remarkable.

Abstract:Aiming at the old oil fields with high temperature and high salinity，which cause more and more serious heterogeneity after long-term water flooding，Huabei oil field was taken as the research object. A hydrophobic polymer was developed by using acrylamide and acrylic acid as the main reaction monomers and introducing temperature and salt resistant monomer NVP and hydrophobic functional monomer，and a weak gel system with temperature and salt resistance was prepared through the crosslinking reaction between the polymer and the phenolic aldehyde resin crosslinking agent. The temperature and salt resistance，injectability plugging performance and fluid flow steering capacity of the weak gel system was measured. The results showed that when the concentration of polymer was 2000 mg/L，the polymerization cross ratio was 1∶1.5，the concentration of auxiliary agent amine persulfate was 2000 mg/L，the gel strength was higher than 1000 mPa·s at the reservoir temperature of 120 ℃ and the salinity of 37950.2 mg/L，moreover，the viscosity retention rate was more than 80% after aging for 90 days，which indicating that the weak gel had good temperature and salt resistance. It was observed that the micro network framework of weak gel after aging for 90 days was obvious，exhibiting good stability. The core flow test results showed that the weak gel system had good injectability. Under different permeability levels，the liquid flow diversion effect was obvious after the weak gel was blocked. The increase of the diversion rate of the low-permeability layer was as high as 48.33%，and the improvement ability of the water absorption profile was good. The sand filled pipe with different permeability was used for plugging，and the pressure measuring points of the sand filled pipe were pressurized in turn，the weak gel had good migration ability and the plugging rate was all over 85%.

Abstract:Aiming at the problems of high reservoir temperature， unbalanced injection and production， and prominent contradictions between layers in the late development stage of high water-cut oil reservoirs in medium and high permeability reservoirs，a high temperature resistant and high viscosity elastic profile control and plugging agent was prepared by taking high viscoelasticity gel powder as the main agent，adding a certain amount of urotropine，sodium hydroxide，water swelling granular plugging agent and one-way pressure sealing agent. The gelling performance，thermal stability，plugging performance and compatibility with CO₂ of the profile control and plugging agent were evaluated，and the field application was mentioned. The optimized formula of the plugging agent was as follows：2% high viscoelastic gel powder+4% granular plugging agent+4% single pressure sealing agent+0.9% urotropine+1.0% sodium hydroxide. The plugging agent could not form a gel at room temperature and could be smoothly pumped into the formation to ensure construction safety. After curing at the temperature of 120℃ and 150℃，the gelling time of the plugging agent was 492 min and 286 min，respectively，and the gelling viscosity was 11806 mPa·s and 11250 mPa·s，respectively，resulting in forming a high viscoelastic semi-solid gel. The plugging agent had a temperature resistance of above 150 ℃ ，good pressure bearing capacity and selectivity，and could achieve targeted plugging，effectively control the dominant water flow channel of the reservoir，and improve the water absorption profile. The plugging agent had a significant effect in on-site application. After the shallow profile control of L90-58 well，the average daily oil production of the corresponding oil well increased by 3.38 t，and the water content decreased by 19.15%，achieving good water control and oil increase effects.

Abstract:Based on the problems of rich heavy oil，serious heterogeneity and poor water drive development effect in Bohai reservoir，it is not ideal to using particle diversion agent or heavy oil emulsifier alone to enhance oil recovery. The performance of the complex system of emulsifier，polymer microspheres and gel dispersions for heavy oil in LD5-2 heavy oil reservoir in Bohai Sea and the effect of liquid flow diversion were studied by means of laboratory evaluation. The results showed that the median initial particle size of polymer microspheres was 8.7—9.2 μm and the expansion ratio was 2.5—3.0. The dispersion of gel dispersions showed irregular morphology in vitro，and the retarding swelling effect was not obvious. The adsorption of surfactant to diverter particles reduced the effective content of emulsifier in heavy oil and the effect of emulsification and viscosity reduction became worse. However，when the mass ratio of oil to viscosity reduction system reached up to 6∶4，it still had a good viscosity reduction effect. Compared with the particle steering agent alone，the particle steering agent in the binary composite system of heavy oil emulsifier/particle steering agent had good shear resistance，injectability and deep profile control and displacement ability. For reservoirs with large channel or extra high permeability，granular diversion agents must be combined with strong gel to exert synergistic effect of micro and macro fluid diversion.

Abstract:Aiming at the issue of low water flooding efficiency in Bohai X oilfield due to the properties of high porosity，high permeability，strong heterogeneity，high water-oil mobility ratio in reservoir，an in-depth conformance control and flooding technique of controllable self-aggregation microspheres cooperating with emulsification dispersion agent，was proposed to enhance the oil recovery in the study. The self-aggregation property of the microspheres was studied by scanning electron microscope and particle size analysis，the emulsification property of the emulsion dispersion agent was evaluated by stirring emulsification method， and the performance of the two agents in reservoir was evaluated by sand pack experiment. The results showed that the microspheres could implement self-aggregation through the functionalized chains on the surface under reservoir conditions，and the particle size after aggregation was 3.1 times larger than that before aggregation. The injection pressure of the microspheres in sand packing model increased step by step， revealing the good injectivity and deep migration capability of the microspheres before self-aggregation，and the plugging rate after self-aggregation in the sand packing model with the permeability of 2000×10^-3—2600× 10^-3 μm² could be more than 50%. The selected emulsification dispersion agent could emulsify crude oil efficiently. The emulsification rate of crude oil could be 100% as the concentration of the agent was higher than 2000 mg/L，and the micro-homogeneity of the formation could be finely adjusted by emulsified crude oil. There was a good synergistic effect between the microspheres and emulsification dispersion agent. The oil recovery could be increased by 13.1%—18.4% compared with water flooding when the slug ratio of microspheres（6000 mg/L）and emulsification dispersion agent（4000 mg/L）was 1∶1—3∶1 with the total injection volume of 1 PV. The pilot tests showed that the technique proposed could obviously enhance oil recovery，the net oil recovery increased in three months was 3260.41 m³.

Abstract:At present，polymer microsphere deep profile control and flooding technology is mainly used in high water cut old oilfields to control water and stabilize production，but the effect is not ideal. In order to solve the technical problems of poor matching between ordinary polymer microsphere and pore throat， and limited sealing ability， self-aggregation polymer microspheres NEPU-WMJ and NEPU-NMJ were developed. The physical and chemical properties of the microsphere were evaluated using a high-speed freezing centrifuge and an optical microscope. The compatibility of microspheres with pore throat， profile improvement effect，and oil displacement effect were studied through long sand filling tube displacement and dual tube parallel connection method. The research results indicated that compared to NMKY，NM，WM，and YHM microspheres，the self-aggregation polymer microspheres NEPU-WMJ and NEPU-NMJ exhibited better expansion and long-term stability. After aging at the temperature of 120 ℃ for 4—6 days，the average particle size of NEPU-WMJ increased from 2.57 μm to 44 μm，while the average particle size of NEPU-NMJ increased from 0.08 μm to 89 μm. NEPU-WMJ could maintain stable for about 30 days at the temperature of 120 ℃，while NEPU-NMJ could remain stable for more than 90 days. Self-aggregation polymer microspheres could achieve deep migration in the cores with the permeability of 100×10^-3 —1000×10^-3 μm² with strong ability to improve profile. Under the conditions of temperature of 95 ℃ and permeability difference of 5 and 40，the total oil recovery rate was effectively enhanced by over 24%. In high-temperature environments，the self-aggregation of microspheres could effectively block large pores，activate low-permeability layers，achieve micro profile control and flooding，and significantly improve oil recovery.

Abstract:In order to meet the requirement of high-temperature resistance of temporary plugging agent in high temperature-reservoir operation and simplify the process flow of unblocking，under the catalytic effect of inorganic salts，polymer gels was prepared at high temperatures using paraformaldehyde and polyether amines as main raw materials. The effects of temperature and components on the formation time of the polymer gels were investigated，and the mechanical properties and temporary plugging performance of the polymer gels were evaluated by mechanical compression experiments and core displacement experiments. The results showed that there was a slight influence of solvent，paraformaldehyde，and polyetheramine content on the formation time of polymer gels，while the temperature and inorganic salts had a significant effect. The formation time of polymer gels decreased as the temperature increased from 100 ℃ to 160 ℃. At the temperature of 140 ℃，the formation time was 65，50， 25，20 min，respectively，when the inorganic salts was ZnCl₂，CaCl₂，NH₄Fe（SO₄）₂·12H₂O and CdCl₂·2.5H₂O，respectively. Mechanical compression experiments showed that the gels had excellent mechanical strength after cyclic mechanical application under a pressure of 3.57 MPa，the stability of the gells was excellent after aging for 10 days at the temperature of 140 ℃，and the strength retention rate was more than 95% . The core displacement experiment showed that the gels had excellent blocking performance with a temporary blocking pressure of 5.08 MPa and a breakthrough pressure gradient of 84.00 MPa/m. The gels could be broken within 4 h using 10% hydrochloric acid，and the core permeability recovery rate was higher than 100 % after breaking the gel. The c_cmc of the gel breaking liquid was 200 mg/L，and γ_cmc was 29.80 mN/m，which had good surface activity and could improve the oil-washing efficiency. The obtained high-temperature resistant plugging agent had a significant advantage over conventional plugging agents in terms of plugging performance，and its efficient surface activity of the gel breaking liquid was helpful to other oil recovery processes.

Abstract:For reservoirs with high mud content and low permeability，shrinkage swelling agent can reduce pressure and increase injection，but there are no research reports on the relevant mechanisms. In order to solve this problem，the influence of the dosage of shrinkage swelling agent（DSJ-1）containing quaternary ammonium and primary amine groups on the anti swelling rate and shrinkage swelling rate of bentonite was investigated. Then the bentonite before and after treatment was characterized by X-raydiffraction（XRD），X-ray fluorescence spectrum（XRF），Zeta potential，thermogravimetry，particle size distribution and optical microscope. The anti swelling and shrinkage swelling mechanism of DSJ-1 was analyzed. The results showed that during the anti swelling treatment process，DSJ-1 was mainly adsorbed on the surface of bentonite. The adsorption amount and Zeta potential had the greatest impact on the anti swelling rate. During the shrinkage swelling treatment，DSJ-1 was mainly adsorbed between crystal layers. The particle aggregate size and Zeta potential affected the shrinkage swelling rate.

Abstract:In view of the poor stability of polymers in high temperature，high salinity environment，the influence of AMPS，NVP and DMAM on the polymer viscosity，long-term stability，seepage characteristics and oil flooding effects were systematically studied under the class III reservoir conditions of Shengli oilfield. The results showed that the AM-AMPS/20%（20% was the AMPS dosage）solution performed the highest viscosity at concentration of 1500—3000 mg/L and at the temperature of 25—95℃ compared to polymer prepared with other AMPS content，and AM-NVP and AM-DMAM solutions. However，when the calcium and magnesium ion concentration increased from 874.0 mg/L to 5296.0 mg/L，AM-DMAM/10% solution became the best in viscosification. In terms of the effect of the monomer content，the higher the content of the AMPS monomer，the greater the viscosity of the polymer solution；and the opposite effect occurred when it came to the NVP and DMAM monomer cases due to the correspondingly decreased molecular weight of their polymers. The oil recovery tests showed that the AM-AMPS could enhanced oil recovery by 21.9%—24.9% based on the water flooding，while AM-NVP and AM-DMAM polymers could enhance oil recovery by 20.9%—19.8% and 21.1%—20.2%，respectively. AM-AMPS polymer had the strongest oil flooding capacity，among which AM-AMPS/20% performed the highest incremental oil recovery of 24.9%，which was promising to be used in class III reservoir of Shengli oilfield.

Abstract:With the application of polymer flooding，partially hydrolyzed polyacrylamide（HPAM）has the problems of easy hydrolysis and low viscosity in high-temperature and high-salinity（HTHS）reservoir. To meet the requirement of harsh reservoir，a salt-resistant monomer 3-（N-allyl-N-methylamino）propane-1-sulfonate sodium（MAPS）was synthesized using allyl chloride and sodium N-methyl taurate as main materials，and MAPS and acrylamide（AM）were further copolymerized to form a novel salt-resistant polymer P（AM/MAPS）. The product was characterized by infrared spectroscopy and nuclear magnetic hydrogen spectroscopy. The effects of concentration，temperature，salinity and shear rate on the viscosity of P（AM/MAPS）were studied by rheometer. The results showed that the viscosity of P（AM/MAPS）solution with mass concentration of 2000 mg/L reached 14.20 mPa·s under the conditions of the temperature of 85 ℃ and salinity of 3×10⁴ mg/L. In one-dimensional displacement experiment with permeability of 527.73×10^-3 μm² sand pack tube，P（AM/MAPS）could enhanced oil recovery by 13.42% on the basis of water flooding，and the total recovery rate of the double-pipe parallel core with permeability of 882.79×10^-3 ，422.53×10^-3 μm² could enhanced by 9.27%. The salt-resistant polymer P（AM/MAPS）could be efficiently used in polymer flooding technology for HTHS reservoir to enhanced oil recovery.

Abstract:Molecular weight of Polymer is an important parameter to evaluate the injectability of chemical flooding system，which directly affects the field injection pressure and oil displacement effect. In view of the problems of high injection pressure，poor injection and uneven effect of individual well groups in the chemical flooding pilot test area of block S of medium low permeability high pour point oil reservoir，the matching relationship between polymer molecular size and reservoir micro pore throat after cold damage of high pour point oil reservoir was studied by using dynamic light scattering method，microporous membrane method and natural core injectability experiment. Based on the polymer molecular radius of gyration，hydrodynamic size and injectability test results，the polymer molecular weight in block S was adjusted from 2000×10⁴ to 1200×10⁴ ，and the injection thickness ratio of single well was increased from 42%—51% to 64%—85%，which provided a basis for polymer molecular weight adjustment in the pilot area and decision-making in the expansion area.

Abstract:Low permeability reservoirs have the characteristics of small pore throat radius，low permeability and poor water absorption，resulting in unsatisfactory chemical flooding effect. Aiming at this problem，propylene oxide and ethylene oxide were introduced into dodecyl alcohol and sulfonated to obtain alcohol ether sulfonate（DP6E6S）. Then，a compound system of DP6E6S and C₁₆-carboxybetaine（PNC）surfactant was constructed. The surface/interface，aging，adsorption，wettability and emulsification properties of the system were evaluated. Finally，the injection enhancement performance of compound system was explored by core flow experiment. The results showed that PNC and DP6E6S exhibited strong synergistic effect. Compared with a single surfactant，the compound system effectively reduced the critical micellar concentration and surface tension，while enhanced the stability and adsorption resistance of emulsion. The PNC/DP6E6S surfactant system with a molar ratio of 1∶1 and 2∶3 demonstrated strong anti-aging properties. It could maintain the oil-water interfacial tension to 10^-3 mN/m in a wide range of salinity（5%—10%）. After aging at 60 ℃ for 30 days，the oil-water interfacial tension had no obvious change. With the increase of salinity，the emulsion prepared by the compound surfactant would undergo phase transition from Winsor I to Winsor Ⅲ and then to Winsor Ⅱ. The medium phase emulsion exhibited a larger volume and better stability. The average particle sizes of the compound surfactant emulsion with ratios of 1∶1 and 2∶3 reached the minimum value（7.52 and 10.01 μm）at NaCl concentration of 8%. In addition，the compound surfactant solution at these ratios also demonstrated excellent solubilization effect，with oil solubilization up to 68 and 64 mL/g，respectively. The PNC/DP6E6S compound system，with low interfacial tension and high wettability angle，was beneficial for reducing pressure and increasing injection in low permeability reservoir. Compared with water flooding，the depressurization rate of 1∶1 and 2∶3 surfactants could reach 28.9% and 23.9%，respectively，meanwhile the recovery efficiency could be increased by 21.85 percentage points and 18.92 percentage points. The ability of the compound surfactant system with a 1∶1 ratio of PNC to DP6E6S in reducing capillary forces was superior to that with a 2∶3 ratio，resulting in better pressure drop reduction and enhanced oil recovery.

Abstract:It is proven that two-dimensional（2-D）black nanosheets can enhance effectively oil recovery in low permeability and tight reservoirs，showing excellent water/oil（W/O）interface characteristics. In order to clear the influence of molybdenum sulfide nanosheet，the main component of 2-D black nanosheet，on the microscopic characteristics of W/O interface，Lammps was used to establish the model of molybdenum sulfide nanosheet. Firstly，the size of molybdenum sulfide nanosheet was optimized. At room temperature and atmospheric pressure（i.e.，298 K and 1 atm），molecular dynamics simulation was conducted to investigate the effect of the selected size of molybdenum sulfide nanosheets on the oil-water interface. The adsorption morphology of molybdenum sulfide nanosheets at the oil-water interface，the effect of the intersection angle between the nanosheets and the oil-water interface on the interface，and the stress of the nanosheet were analyzed. The simulation results showed that the 30 ? ×40 ? molybdenum sulfide nanosheet had the best effect at the oil-water interface. The presence of molybdenum sulfide nanosheet affected the density， thickness，intersection angle and coverage of oil-water interface. The action mechanism of molybdenum sulfide nanosheet at the oil-water interface was clarified as follows，the stress at each point on the nanosheets affected their intersection angle，which affected the interface coverage rate. However，there was a competitive relationship between the intersection angle and the interface coverage rate，which affected the fluctuation of oil-water interface tension. This study clarified the influence of molybdenum sulfide nanosheet on oil-water interface characteristics，and laid a theoretical foundation for the study of oil displacement mechanism of 2-D black nanosheet.

Abstract:There are some problems in the development of heavy oil reservoir in Shengli oilfield，such as high viscosity and poor fluidity of crude oil，leading to unsatisfactory water drive recovery. To address this issue，an emulsification-stripping dual effect system consisting of betaine-based surfactant（CBT）and anionic/non-ionic surfactant（ASC）was constructed using emulsification instability coefficient，oil film shrinkage rate，and minimum emulsification speed as indicators. The emulsification and stripping ability of the dual-effect system for heavy oil was evaluated by indoor sand filling flow experiments，and then its mechanism was studied by using microscopic model. The results showed that CBT had excellent emulsification performance and significantly reduced the oil-water interfacial tension for heavy oil，while ASC had well stripping ability for heavy oil. The composite system had excellent emulsification and stripping properties. The dual-effect system increased the washing efficiency and changed the flow direction by emulsifying residual oil. At the same time，the wetting and osmosis of the system promoted the shrinkage and stripping of oil film on the solid wall. Under the condition of CBT/ASC composite system with a mass ratio of 3∶2 and the dosage of 0.3%， the recovery rate reached 50.36%，which increased by 14.18 percentage points comparing with water flooding. It had important guiding significance for the efficient development of heavy oil reservoir.

Abstract:In order to improve the efficiency of emulsification and viscosity reduction development of super heavy oil reservoirs，the functional monomer N-benzyl-N-alkylacrylamide（DTAM）was first prepared using acrylamide（AM），N，N-di N-methylformamide（DMF），bromoalkane and benzyl bromide as raw materials. Then the amphiphilic polymer（PBS-2）was prepared from AM，2-acrylamido-2-methylpropane sulfonate（AMPS）and DTAM. The structure of the polymer was characterized using infrared spectroscopy，nuclear magnetic resonance spectroscopy，and elemental analysis. The synthesis condition of PBS-2 was optimized using the viscosity reduction rate of synthesized product as an evaluation indicator. The interfacial activity，wetting performance，and emulsification and viscosity reduction performance of PBS-2 for heavy oil with different viscosities were evaluated. The results showed that the optimum synthesis condition for PBS-2 was obtained as follows：90∶4∶6 the molar ratio of AM，AMPS and DTAM，25% the total mass fraction of monomers，0.4% the mass fraction of initiator azodiisopropyl imidazoline hydrochloride，50 ℃ reaction temperature，and 6 hours reaction time. The interfacial activity of PBS-2 was strong. When its mass concentration reached 3 g/L，the oil-water interfacial tension value could be reduced to the order of 10^-2 mN/m. PBS-2 had good wetting performance. When the mass concentration of PBS-2 solution increased from 0 to 5 g/L，the contact angle between it and heavy oil decreased from 113.2° to 32.9°. The wettability of the heavy oil surface changed from lipophilic to hydrophilic. PBS-2 had a good emulsification and viscosity reduction effect on super heavy oil. When the mass concentration of PBS-2 was 3 g/L，the viscosity reduction rate of super heavy oil samples with viscosity ranging from 10.5 Pa·s to 112.5 Pa·s could reach over 99%. The synthesized amphiphilic polymer PBS-2 could effectively emulsify and peel off heavy oil，improve the flowability of heavy oil， meet the needs of emulsification and viscosity reduction of super heavy oil，and then provide reference for the development of chemical viscosity reduction in super heavy oil reservoirs.

Abstract:The ultra-heavy oil in Tahe oilfield is currently produced by mixing light oil with ultra-heavy oil in wellbore to reduce viscosity. However，the high ratio of needed light oils and abnormal fluid production caused by uneven mixing lead to an inefficient production with high cost. Based on the characteristic of high asphaltene content in Tahe ultra-heavy oil，a high-porosity Ni-Mo catalyst based on γ-Al₂O₃ carrier was synthesized using 1，3-propanediol，ammonium paramolybdate，and nickel nitrate as raw materials. Its catalytic effect on viscosity reduction was evaluated. The results showed that the trilobal γ-Al₂O₃ catalyst carrier had a cylindrical pore structure. The pore diameter was mainly 5—11 nm. The Ni-Mo catalyst could reduce the viscosity（50 ℃）of ultra-heavy oil from 28 200 mPa s to 298 mPa s. The viscosity reduction rate was 98.94%. In addition，it could reduce the density of ultra-heavy oil from 1.0070 g/mL to 0.8724 g/mL. Simultaneously，the content of saturated hydrocarbon increased significantly， while the content of resin and asphaltene decreased significantly. The catalytic ex-situ upgrading technology for viscosity reduction combined with reinjection of upgraded oil into wellbore could effectively reduce the viscosity of ultra-heavy oil. The catalytic ex-situ upgrading had a good effect，which could effectively save light oil consumption and improve the production efficiency.

Abstract:An N-doped carbon dots corrosion inhibitor was synthesized by microwave method to improve the corrosion problem of ground pipe network under sulfur-containing acidic high-temperature environment. Its corrosion inhibition effect on N80 carbon steel in simulated solution at 25 ℃，60 ℃ and 90 ℃ was tested by electrochemical and weight loss methods. The results showed that the efficiency of corrosion inhibitor（ECI）increased with the increase of the temperature. The ECI reached the maximum of 94.16% at the temperature of 25 ℃ at the NCDs dosage of 150 mg/L. The maximum was 82.92% at the temperature of 60 ℃ at the NCDs dosage of 200 mg/L. At the temperature of 90 ℃ and at the NCDs dosage of 150 mg/L，it reached up to 69.59%. The analysis of corrosion morphology showed that the depth and number of corrosion pits on the steel were the largest at the temperature of 90 ℃. The adsorption isotherm curve showed that the adsorption equilibrium constant of NCDs was the largest at 90 ℃，but the local corrosion was more serious at high temperature. In addition，it is found that the adsorption type of N-doped carbon dots was physical and chemical mixed adsorption. The carbon dots corrosion inhibitor could effectively solve the corrosion of ground pipelines at high temperature and prolong the service life.

Abstract:There are many factors inducing asphaltene deposition，but the influence and mechanism of inorganic salts and minerals on asphaltene stability are not clear. Aiming at the samples of crude oil and asphaltene sediment in four oil areas with asphaltene deposition problems，the composition and elements of crude oil，the physical parameters of asphaltene sediment elements and aqueous solution were measured and analyzed by four component analysis，high temperature simulated distillation，Fourier transform infrared spectroscopy and X-ray fluorescence spectroscopy，and the effects of inorganic salts on the properties of asphaltene dispersant were evaluated. The experimental results showed that the asphaltene deposition of crude oil sample A was due to the unstable asphaltene clusters in the crude oil，and the colloidal instability index CII value reached 1.1. While the deposition of crude oil samples B and C was caused by the contamination from drilling and completion fluid. Most inorganic elements in crude oil and asphaltene sediment samples came from reservoir，while Br element came from brominated salt in drilling and completion fluid. Inorganic bromine salts could produce strong gravitational action of ion-ion or ion -dipole with asphaltene molecules and destroyed the colloidal stability in crude oil. The decrease of inorganic salt concentration would weaken the interference of inorganic salt ions on the interaction between asphaltene and dispersant molecules，and greatly improved the performance of dispersant. The research results provided a reference for preventing asphaltene deposition and alleviating deposition damage.

Abstract:An N-doped carbon dots corrosion inhibitor was synthesized by microwave method to improve the corrosion problem of ground pipe network under sulfur-containing acidic high-temperature environment. Its corrosion inhibition effect on N80 carbon steel in simulated solution at 25 ℃，60 ℃ and 90 ℃ was tested by electrochemical and weight loss methods. The results showed that the efficiency of corrosion inhibitor（ECI）increased with the increase of the temperature. The ECI reached the maximum of 94.16% at the temperature of 25 ℃ at the NCDs dosage of 150 mg/L. The maximum was 82.92% at the temperature of 60 ℃ at the NCDs dosage of 200 mg/L. At the temperature of 90 ℃ and at the NCDs dosage of 150 mg/L，it reached up to 69.59%. The analysis of corrosion morphology showed that the depth and number of corrosion pits on the steel were the largest at the temperature of 90 ℃. The adsorption isotherm curve showed that the adsorption equilibrium constant of NCDs was the largest at 90 ℃，but the local corrosion was more serious at high temperature. In addition，it is found that the adsorption type of N-doped carbon dots was physical and chemical mixed adsorption. The carbon dots corrosion inhibitor could effectively solve the corrosion of ground pipelines at high temperature and prolong the service life.

Abstract:With the development of carbon neutral goals in China，petroleum is facing a lot of pressure to reduce carbon emission. Taking low carbon treatment of shale gas fracturing fluid flowback as the goal，the characteristics and potential impact on water quality of shale gas fracturing fluid flowback were analyzed. The existing processing technology and principle were introduced. It was pointed out that the shale gas fracturing fluid flowback process should proceed from three aspects，such as reducing the pollutant emissions，energy recovery and utilization，saving energy and reducing consumption. Furthermore，it was suggested that these technologies，such as less or no water fracturing technology，clean fracturing fluid technology，new microbial treatment technology，energy saving treatment technology of fracturing flowback fluid，new energy replacement technology and energy saving technology of intelligent equipment，should be vigorously developed and promoted in the development of oil and gas fields， which ensured the reasonable development and sustainable development of shale gas.

Abstract:Oligomeric surfactants，as a novel class of surfactant with superior efficiency at very low concentration，have shown promising applications in the fields of enhanced oil recovery，pharmaceuticals，corrosion inhibitors，and so on. Oligomeric surfactants are composed of two or more amphiphilic moieties，which are chemically linked by a spacer group. They bridge the gap between monomeric surfactants and polymeric surfactants. With the help of the spacer group，the spatial distance of multiple amphiphilic moieties becomes closer，contributing to the stronger aggregation ability of the oligomeric surfactants. Meanwhile，the structure of the spacer group and the topological configuration are more diversified，resulting in multifarious transition processes of molecular configuration and aggregation morphology. These characteristics make them show unique advantages as highly-efficient oilfield chemicals and stimuli-responsive soft materials. But the difficult synthesis processes have been identified as the bottleneck of their systematic investigations. In this review，the synthesis methods of linear，star-like and ring-type oligomeric cationic surfactants，which were classified by the spatial topological structure，were summarized in detail. Specially，some facile reaction routes using polyols，polyamines，polyphenols，polyepoxides and polycarboxylic acids（esters）as raw materials were introduced in detail. Through these reaction routes，star-shaped intermediates，which were the backbone of spacer groups，could be well prepared based on some active groups such as hydroxyl，amino，carboxyl and ester groups. Then star-shaped oligomeric cationic surfactants could be smoothly synthesized after the quaternization of terminal groups of the intermediates. By summarizing the synthesis routes of the above three series of oligomeric surfactants，it was suggested that the combination of esterification reaction， amidation reaction，Schiff base reaction and ring-opening reaction could be used to design and prepare novel oligomeric cationic quaternary ammonium surfactant，which was stimuli-responsive and biocompatible.

Abstract:As reservoir types and wellbore structures become more diverse and complex，advanced，efficient，and stable EOR techniques and stimulation are critical to achieving cost-effective production of oil and gas resources in complex reservoirs and wells. With its low density，high viscosity，effective protection of oil and gas reservoirs，strong profile control and water plugging ability and perfect oil displacement mechanism，foam has achieved good field application results in drilling and completion， cementing，reservoir protection，reservoir transformation and enhanced oil recovery. Based on the introduction of foam theory，the laboratory studies and field tests of foam fluid in various fields of unconventional oil and gas reservoir development in recent years was summarized，the advantages and disadvantages of enhanced oil recovery and stimulation measures was analyzed，and its future development direction was forecasted.